Nov 1, 2007
Executives
Kenneth L. Matheny - Vice President of Investor Relationsand Public Affairs Clarence P.
Cazalot, Jr. - President and Chief ExecutiveOfficer Janet F.
Clark - Executive Vice President and ChiefFinancial Officer Gary R. Heminger - Executive Vice President and President ofRefining, Marketing and Transportation Philip G.
Behrman - Senior Vice President - WorldwideExploration Steven B. Hinchman - Senior Vice President - WorldwideProduction Garry L.
Peiffer - Senior Vice President - Finance andCommercial Services
Analysts
Doug Terreson - Morgan Stanley Doug Leggate - Citigroup Mark Flannery - Credit Suisse Nicki Decker - Bear Stearns Neil McMahon - SanfordBernstein John Herrlin - Merrill Lynch Mark Gilman - TheBenchmark Company Paul Y. Cheng - Lehman Brothers Stephen Beck - Jefferies & Company Michael LaMotte - JPMorgan
Operator
Please standby. Goodday, and welcome to Marathon Oil's third quarter earnings conference call.
As areminder, today's call is being recorded. For opening remarks and introductions, I would like to turn theconference over to Mr.
Ken Matheny, Vice President of Investor Relations andPublic Affairs. Please go ahead, sir.
Ken Matheny
Thank you very much, Erica. I, too, would like to welcome everybody toMarathon Oil Corporation's third quarter 2007 earnings webcast and conferencecall.
As areminder for thetelephone participants, you can find thesynchronized slides that accompany this call on our website, www.Marathon.com. With us on thecall today areClarence Cazalot, president and CEO, Janet Clark, executive vice president andCFO, Gary Heminger, Marathon executive vice president and president of ourRefining, Marketing and Transportation organization, Phil Behrman, senior vice presidentof Worldwide Exploration, Steve Hinchman, senior vice president of WorldwideProduction, and Garry Peiffer, senior vice president of Finance and CommercialServices for our downstream.
Slide 2 contains theforward-looking statement and other information related to this presentation. Our remarks and answers to questions todaywill contain certain forward-looking statements that aresubject to risks and uncertainties that could cause actual results to differmaterially from those expressed or implied by such statements.
Inaccordance with Safe Harbor Provisions of thePrivate Securities Litigation Reform Act of 1995, Marathon Oil Corporation hasincluded in its annualreport on Form 10-Qfor the year endedDecember 31, 2006 and subsequent forms 8-K and 10-Q cautionary languageidentifying important factors, but not necessarily allfactors that could cause future outcomes to differ materially from those setforth in theforward-looking statements. Now turning to slide number 3, net income for thethird quarter was $1 billion versus $1.6 billion inthe third quarter2006.
This slide also provides areconciliation of net income to adjusted net income by quarter for thelast three years. Thebar graphs on slide 4 show thequarterly net income adjusted for special items for thethird quarter, which is just over $1 billion, down $528 million inthe third quarter of2006, and for ease of comparison, this slide also provides thequarterly and yearly data for 2006 and 2005.
Slide 5 shows that on aper share basis,adjusted net income was down $0.67 or 31% from theyear-ago third quarter level, and $0.77 pershare, or 34% below thesecond quarter 2007. Because theWestern acquisition was pending during thethird quarter, there were minimal share purchases during thequarter.
Moving to slide number 6, theyear-over-year decrease inthird quarter net income adjusted for special items was largely aresult of a lowerrefining and wholesale marketing gross margin, partially offset by lower incometaxes. We moveon to slide number 7, adjusted net income for thethird quarter 2007 was $532 million lower than thesecond quarter 2007, and this decrease was also primarily aresult of a lowerrefining and wholesale marketing gross margin, again, partially offset by lowerincome taxes.
Turning to slide number 8, upstream segment income for thethird quarter increased $79 million over thesecond quarter 2007. This increase was theresult of higher natural gassales volumes and higher liquid hydrocarbon sales prices, partially offset byhigher income taxes, lower revenue associated with storage volumes inIreland and higher operating costs primarily related to work-over in the Gulfof Mexico, United Kingdom and Gabon.
As shown on slide number 9, worldwide sales volumes on abarrel of oil equivalent basis increased 33,000 barrels of oil equivalent perday in thethird quarter of 2007 as compared to thesecond quarter 2007 and theaverage realized price barrel oil equivalent increased $0.97 quarter overquarter. Moving on to slide number 10, domestic upstream incomedecreased $26 million from thesecond quarter, largely aresult of slightly higher operating costs associated with thepreviously mentioned work-over inthe Gulf of Mexico.
As shown on slide number 11, theNYMEX prompt price perWTI crude was up$10.13 per barrel fromthe second quarter,while our average domestic realized liquid hydrocarbon price was up $8.34. Our lower realizations compared to theNYMEX were primarily theresult of weaker differentials for Gulf Coast and Wyoming crude streams, aswell as NGL price realizations, which did not keep pace with theWTI increase.
Thebid week natural gasprice was down $1.39 permillion BTUs from thesecond quarter, while our domestic natural gasrealizations were down $1.02 perMcf, our lower 48 realizations were down $1.13 perMcf, primarily reflecting therelative positive movement of differentials to Henry Hub quarter on quarter. Turning to slide number 12, third quarter domestic upstreamexpense, excluding exploration expense was $1.64 perBOE higher in thesecond quarter, primarily as aresult of the higherwork-over expenses already discussed.
Domesticupstream income per barrel of oil equivalent decreased $2.08 quarter overquarter. Moving to slide 13, international upstream income for thethird quarter increased $105 million over thesecond quarter, as aresult of higher volumes and higher realized prices, which were partiallyoffset by higher income taxes, lower revenue associated with storage volumes inIreland, higher operating costs, primarily from work-over inthe United Kingdom andGabon and increased DD&A due to higher EG gassales to the LNGplant.
As shown on slide 14, our international liquids realizationsincreased approximately $9.35 perbarrel, while Dated Brent increased only $5.99 perbarrel. This out performance compared toDated Brent was primarily due to higher market premiums for our light sweetsales, as well as thetiming of lifting.
Theincrease in theinternational natural gasrealization as compared to thesecond quarter was aresult of higher volumes and higher realized prices inEurope. These gains were partiallyoffset by much higher gasvolumes to our LNG facility inEquatorial Guinea during thethird quarter, which was its first full quarter of operation.
Please remember that our LNG business is reported through theintegrated gas segment,so there is anadditional uplift invalue realized by this facility that is not reported through our upstreambusiness. Turning to slide 15, third quarter international upstreamexpense, excluding exploration expense, decreased $0.90 perbarrel of oil equivalent over thesecond quarter 2007, largely aresult of the highervolume of natural gasproduction in EG.
Total income perbarrel of oil equivalent increased $2.97 to $15.65, primarily due to thehigher realizations. Now, moving on to our downstream business inslide 16, third quarter 2007 segment income totaled $482 million compared tojust over $1 billion earned inthe same quarter lastyear.
Because of theseasonality of thedownstream business, I will compare our third quarter 2007 results against thesame quarter of 2006. Themost significant factor contributing thedown-stream's lower segment income quarter over quarter was that theprice of crude oil rosesignificantly during thethird quarter 2007, while inthe third quarter2006, prices fell substantially.
This was theprimary reason our crude oil and other feedstock acquisition costs increasedsubstantially more, and thechange inthe average price ofLLS during theSeptember 2007 quarter compared to theSeptember 2006 quarter would indicate. Due to these escalating prices inthe third quarter of2007, we took a chargefor crude and feedstock derivative activity.
This charge wasn't completely offset by changesin thevalue of theunderlying crude and feedstock inventories and purchases. Theopposite effect occurred inthe third quarter2006, when prices declined during thequarter, and we recorded again on crude and feedstock derivative activity.
Inaddition, the averagesweet/sour differential narrowed about $2 perbarrel between theperiods, which also negatively impacted earnings. And finally, we ran asweeter crude oil slate inthe third quarter 2007compared to the thirdquarter 2006, which also increased our crude acquisition costs quarter toquarter.
Inaddition to theincreased cost ofcrude and feed stocks, theincrease in ourwholesale sales price realizations pergallon during thethird quarter 2007 over thecomparable prior year period was less than theincrease in theaverage spot market prices for theproducts that are usedin theLLS 6-3-2-1 calculation. Inaddition to thederivative effects I just discussed inthe third quarter2007, we had a smallderivative loss related to ethanol versus alarge derivative gain inthe third quarter2006.
This swing was primarily due to thefact that during thethird quarter 2006, we had anumber of derivative contracts inplace to hedge long-term ethanol purchase contracts. When prices fell inthe third quarter2006, the derivativescontracts increased invalue, generating apositive income effect without any offsetting effect from thephysical ethanol purchase contracts during this same quarter.
Intotal, Marathon's refining and wholesale marketing gross margin includedderivative losses of $360 million inthe third quarter of2007 compared to derivative gains of $384 million inthe third quarter of2006. Since we have elected not to use hedge accounting for ourdownstream, all of ourderivative activities arerequired to be marked tomarket by FAS 133.
Therefore, thederivative changereflects both therealized effects of derivatives, as well as theunrealized effect of marking open derivative positions to market. Inaddition, derivatives used innon-trading activities have anunderlying physical commodity transaction.
However, theincome effect related to thederivatives, and income effect related to theunderlying physical transactions may not necessarily berecognized in netincome in thesame period. Thedownstream segment also incurred higher costs inthe third quarter 2007compared to the samequarter last year, primarily because of higher planned turnaround expenses.
Inthe third quarter2007, the crude oil intransit effect, was anegative $30 million versus apositive of $53 million inthe same quarter last year. Partially offsetting these negative results was thefact that the Chicagocrack spread inparticular was much stronger inthe third quarter 2007than it was inthe same quarter lastyear.
TheLLS 6-3-2-1 crack spread on atwo-thirds Chicago and one third U.S. Gulf Coast basis increased from $7.15 inthe third quarter 2006to $9.01 in thethird quarter of 2007.
Our refineries operated well last quarter. Crude oil throughputs improved from 1, 031,000barrels per day inthe third quarter of 2006to 1, 042,000 barrels perday in thethird quarter of 2007.
However, planned turnarounds under way atthe end of thethird quarter at ourCatlettsburg, Kentucky and St. Paul Park, Minnesota refineries reduced ouraverage third quarter 2006 total crude and other charge and blendstock stockinputs to 1,241,000 barrels perday compared to 1,249,000 barrels perday in thesame quarter last year.
For the fullyear, we expect our total crude oil throughputs will exceed the record level of980,000 barrels per day we achieved in 2006. As shown on slide 17, Speedway SuperAmerica's gasoline anddistillate sales were up 25 million gallons, anincrease of 2.9% quarter-over-quarter.
SpeedwaySuperAmerica same-store gasoline sales volumes were up 1.9%. Thesame-store merchandise sales increased 2.6% inthe third quarter 2007compared to the samequarter of 2006.
And last, SpeedwaySuperAmerica's gross margin for gasoline and distillate was $11.03 pergallon compared to $14.01 pergallon in thesame quarter last year. Slide 18, provides asummary of segment data, along with reconciliation to net income.
Of note is theintegrated gassegment, which had income of $52 million during thethird quarter 2007 compared to $12 million inthe second quarter. Theincrease in earningsis primarily attributable to thefact that the thirdquarter was the firstfull quarter of operations for theEG LNG production facility, which commenced primary operations inMay of 2007.
Slide 19, provides selected preliminary balance sheet andcash flow data. Cash adjusted debt to total capital atthe end of thethird quarter was approximately 11%.
As areminder, the cashadjusted debt balance includes approximately $508 million of debt, serviced byU.S. Steel.
Year-to-date preliminary cash flowfrom operations was approximately $3 billion, and preliminary cash flowfrom operations before working capital changeswas approximately $4.6 billion. Slide 20, provides theguidance for the fourthquarter and for thefull year 2007.
Now, before I turn thecall over to Clarence, there area few additionalcomments I would like to make. This willbe my last conferencecall with investors, as I have decided to retire atthe end of theyear after more than 30 years with Marathon.
More than seven of those years have been spent working withinvestors. Nearly 40 conference calls,hundreds of meetings and literally thousands of telephone calls.
While I amlooking forward to retirement, I would beremiss if I did not sayhow much I've enjoyed thetime spent with all ofyou. You have challenged mewith questions and I have benefited from your knowledge and your insights.
You kept meon my toes, and I think it's safe to sayI've gained more from theexperience than you. I will miss thechallenge, but most of allI will miss therelationships and theopportunity to talk with you on aregular basis.
But this is really agood news story. Thetiming is right.
Marathon is positionedwith a managementteam, employees, and anasset base that's as good as any I have seen inmy 30-year career. Thegood news for meis that I'm healthy and will have time to domost anything my family wants meto do.
Thegood news for allof you is that Howard Thill will replace me. Many of you know Howard very well andrecognize that he ismore than qualified for thejob.
Howard, along with Michol Ecklundand Bonnie Chisum will behere to meet all ofyour investor needs. And I can guarantee investor relations atMarathon will not miss abeat.
Infact, the beat willprobably step up anotch. So, for thelast time my thanks to allof you.
It's been agreat ride. Now I'll turn thecall over to Clarence.
Clarence Cazalot
Ken, thank you somuch. We still got two more months toask you questions and challenge you abit.
I, on behalf of thecompany, want to thank you again. Ken,as you all know, hasmade tremendous contributions to Marathon for over 30 years and certainly frommy standpoint.
Having worked with him for thelast six years, youknow what a gentleman heis, a manof great integrity, and he's been agreat source of advice and guidance for mepersonally. So, I want to wish Ken and Pegall thebest as they take on new challenges and to congratulate Howard on thejob, and we look forward to working with Howard as well.
As Ken pointed out inthe third quarter, ourupstream business benefited from theincrease in crude oilprices, while it was achallenging environment for our downstream sector, as margins were compressedby increased crude costs. This certainly points out thevolatility in ourbusiness, but also theadvantage of being astrong integrated company.
Despite thisnear-term volatility, we continue to invest inprofitable, long-term growth opportunities and I think as you allrecognize, our clear intent is to create long-term value through fullyintegrated solutions. Such as thepotential linkage of our recently acquired interest inthe Canadian oil sandswith our best in classU.S.
refining and marketing assets. Andas you recognize, we just announced yesterday approval of our Detroit refineryupgrade and expansion project.
When completed in2010, this refinery project will allow us to process anadditional 80,000 barrels of heavy oil and unlock additional value from our oilsands assets. And I know there's agreat expectation out there about what theprecise downstream value proposition is.
Gary Heminger is going to outline for you inan illustrated fashionin just afew moments the valueproposition we seeusing a reasonable setof assumptions. But before Gary doesthat, I would like Steve Hinchman to give you anupdate on our production business.
Steve?
Steve Hinchman
Thank you Clarence. Ourupstream segment had strong operational performance inthe third quarter,including our new LNG facility inEquatorial Guinea, which achieved anaverage utilization rateof 93% of design capacity.
Unfortunately on October 4 we discovered asmall leak in a2-inch drain line within therefrigeration unit requiring afull shut-in of theplant. Theleak has been isolatedand repairs are underway.
Theplant should be backonline and manufacturing LNG within thenext couple of weeks. This outage will impact our annualized production volumes byabout 7500 barrels of oil equivalent perday, as reflected in thefourth quarter guidance.
InNorway, the Alvheim FPSOconstruction has beencompleted and commissioning, although taking longer than we expected is nownearly complete. We expect to sail out of theHaugesund shipyard by mid-December.
We'll stop inAmofjord, which is near Stavanger, to install thethrusters and commission thefirewater and seawater pumps before sailing to location. First production is expected inthe first quarter.
This depends on having aweather window conducive to safely linking thevessel to the loadingbuoy. Our production for theyear will fall within theprior guidance 350,000 to 375,000 barrels of oil equivalent perday, but near the lowend, attributable to these two events.
Now, Gary Heminger will make his additional comments.
Gary Heminger
Thanks, Steve. AsClarence mentioned, we closed theWestern transaction on October 18, 2007 and yesterday, we announced theapproval of theDetroit upgrade and expansion project.
Butbefore I get into thelinkage between these projects and thevalue proposition for Marathon, I would like to welcome Steve Reynish and histeam to Marathon. We areexcited not only to have theWestern assets, but we arealso pleased to have been able to retain thehighly talented staff, which Steve will lead as President of Marathon OilCanada.
Steve most recently was theExecutive Vice President and Chief Operating Officer of Western and prior tothat was the Presidentand Chief Operating Officer of Albion Sands Energy, which operates theMuskeg River Mine on behalf of theAthabasca oil sands project owners. Steveand his team bring valuable knowledge to the operation of the business.
To help investors, analysts and other interested partiesbetter understand our value proposition we have prepared thefollowing slides to compare our project with that of atypical Alberta upgrader. I want to emphasize that this example provides anillustrative case of thepreliminary value proposition and hopefully, you will recognize that we have along way to go with thecommercial negotiations around areas such as transportation and diluent, sothis analysis is not intended as areflection of our economic case for theproject.
Slide 22, provides therelevant assumptions used inthe rest of thispresentation. While I won't go overthese individually, I felt itimportant that you seewhat the base for thisillustrative case areand that they arereasonable and not based on themuch higher crude prices we've seen recently, or thehigher crack spreads refiners had this past summer.
Moving on, slide 23 illustrates, thetypical value chainmoving from bitumen to refined products, using thepreviously outlined price assumptions. Thisslide reflects thethree value chainoptions available to aCanadian heavy oil producer, selling Dilbit, upgrading to asynthetic crude oil, or gaining access to arefinery with heavy oil capability.
As shown here and as further demonstrated inthe following slides, theMidwest refinery option clearly provides thehighest value. Moving to slide 24 and using thevalue chain justdemonstrated, thevalue of linking our AOSP production with our Detroit refinery is furtherdemonstrated.
This slide reflects themargin value of aMidwest refinery, heavy oil upgrading solution on abitumen basis. Starting with the70/30 blend or one barrel of bitumen and 0.43 barrels of diluents and using thepreviously stated price assumptions, adding $10 perbarrel for transportation refinery expenses, this refinery feedstock of 1.43barrels is then converted into finished products valued atapproximately $94.60.
Theresult of this value chainis a margin of $21.74 perbarrel of bitumen. Slide 25, reflects themargin value calculation of thetypical Alberta up-grader.
This optionalso starts with one barrel of bitumen, but thediluent is recycled to themine for repeated blending purposes. Other blend stocks of approximately 0.21 barrels arenecessary to optimize theup-grader option.
Itis estimated that total costs, including feedstocks and blend stocks,transportation, operating expense and overhead areapproximately $13.61 perbarrel of bitumen. Theresulting blend of products reflects ayield of approximately 103% as aresult of theexpansion that occurs during upgrading of thebitumen barrel.
Product output of theup-grader consists of amix of premium synthetic crude oil, vacuum gasoil, and heavy synthetic crude oil, which yields $63.44 of revenue for everybarrel of bitumen processed, resulting inan operating margin of$19.54 per barrel ofbitumen. Slide 26 with aside-by-side comparison illustrates thetotal value advantage of aMidwest refinery heavy upgrade oil solution, compared to anAlberta up-grader using thestated assumptions.
As illustrated on theprevious slides, there's anoperating margin advantage of approximately $2.20 perbarrel. Inaddition, as shown here, we estimate there is anadditional value of approximately $1.25 perbitumen barrel, when taking capital costs into consideration.
This calculation imputes amarket value for base refinery to truly reflect comparable costs. Intotal, we believe Marathon's integrated solution hasapproximately a $3.50 perbarrel, per bitumenbarrel competitive advantage to upgrading atthe field level.
And with this solution, we aresupplying refined product directly to amarket that currently hasexcess demand. And of course, we arestill in theearly days of our Canadian oil sands project and we will continue to exploreour options for gaining value from this asset.
We continue to look atother potential long-term refining solutions within our network. And we look forward to working with our partners on thepromising future of theAOSP project, including discussions about technology opportunities, and optionsfor optimizing thevalue of the currentup-grader.
Let mefinish by taking a fewminutes to remark on theAlberta royalty changesoutlined and Premier Stelmach's address last week. While we would have preferred that there would have beenlimited changes to theroyalty regime, we believe there is minimal effect based on thepricing assumptions we used.
Itis disappointing theroyalty will graduate with oil prices and that may limit upside and futurecapital spending. We will obviously continue to study and follow theopen items still being discussed inthe provincepertaining to bitumen upgrading.
We areconfident Marathon will deliver asuperior competitive solution to theintegration of the oilsands with our refining system. We willupdate you as we continue down this path of integration.
Now I'll turn thecall back to Kenneth.
Ken Matheny
Okay. Thank you verymuch, Gary.
Erica, we will now open thecall to questions. I would like toremind you to accommodate allthose who want to ask questions, we ask that you limit yourself to onequestion, plus afollow-up.
You may re-prompt for additional questions as time permits. And for thebenefit of all listeners,we ask that you identify yourself and your affiliations.
Operator
(Operator Instructions) We'll hear first from Doug Terreson withMorgan Stanley.
Doug Terreson -Morgan Stanley
Good afternoon, everyone, and congratulations, Ken.
Ken Matheny
Thank you Doug.
Doug Terreson -Morgan Stanley
My question might befor Gary or maybe Clarence, and itinvolves the refiningand marketing business and specifically theexpansion that was announced yesterday, inthat the strategicbenefits of theexpansion obviously arepretty clear. But on thefinancial side, I wanted to seewhether or not there were any local or state tax incentives or advantages thatmight enhance economics of that project and if you could talk about them, couldyou tell us what they are?
Ken Matheny
Gary?
Gary Heminger
Sure. Yes, Doug, wehave spent a lot oftime working with theCity of Detroit and theMichigan economic development committee and we have been very fortunate to havereceived approximately just north of $150 million net present value intax advantages in thisproject.
Doug Terreson -Morgan Stanley
Okay, good, thanks alot. That covers my question.
Operator
Next we'll hear from Doug Leggate with Citigroup.
Doug Leggate - Citigroup
Thanks. Congratulations,Ken and Howard.
Ken Matheny
Thank you.
Doug Leggate -Citigroup
I've got acouple, if I may. I'll take one and myfollow-up.
But thefirst one is on ethanol. You guys area very large blenderof ethanol.
Prices areat apretty hefty discount right now. Can you help us understand how that impacts your, I guess,your earnings on thedownstream outside of just theindicated crack spread that we seeon the screen andmaybe the outlook asyour blending capacity goes up into 2008?
Garry Peiffer
Yes, this is Garry Peiffer. Obviously, as you stated, thecurrent spot market prices arevery attractive versus thegasoline prices.
I think, as wementioned though, atleast from our particular perspective, as we mentioned last year inthe third quarter, wehave been able to negotiate back starting in'05 some pretty attractive contracts when theprices were relatively lowfor ethanol. Sowhen you look at ourspecific results for us, it's had abig positive effect,but some of that hasbeen muted by the factthat we had some long-term contracts we're comparing ourselves to last yearsame quarter.
Also last year inthe third quarter, aswe mentioned last year, we had some various and as Ken mentioned, we had avery positive derivative effects from some of thelong term contracts weentered into, so Iguess if you look quarter-to-quarter, and you strip out thederivatives effects. We were pretty flat quarter to quarter interms of our results from allthe ethanol blendingwe have done, so, again, part of itdue to the fact wewere very fortunate they have some very good longterm contracts in thethird quarter of last year, and we've been taken advantage on aspot basis more this year, and probably will beinto the future.
We have very little of our future ethanol demand, forecasteddemand under contract atthe moment, probablyclose to about 10%, sowe will be living offkind of spot differentials going forward. And probably won't have alot of derivative activity because we don't have alot of long-term contracts either going forward.
Doug Leggate -Citigroup
Okay Gary, theMagna should can you kind, of quantify, because if you look atspot versus gasoline right now, spot ethanol versus gasoline, on abillion gallons ayear, that could bequite a decent number,right?
Gary Peiffer
Assuming that you will getto keep the differenceall for yourself andthat you don't have to, which we do, discount those gallons to our marketers tohave them sell it. Now, inthe case of what wesell through Speedway SuperAmerica, you're definitely right.
We doget to capture allthat. But to theextent that we have to entice our jobber, our Marathon jobber customers, or ourwholesale customers, alot of those customers aren't inclined to go through theexpense of cleaning their underground storage tanks and aren't inclined to onlywant to buy from one supplier, if we arethey only supplier in themarket.
They, like everyone else, liketo have diversity of supply to ensure they have acompetitive price. It's great to look atthat differential that you just mentioned, but you also got to consider thatyou have to discount, especially insome markets like Illinois, where it's very competitive, we have to discount awaya lot of that, thatbenefit, because everybody does itand everybody's giving themarketers, or trying to squeeze out a$0.01 or $0.02 of margin over and above what they would geton the gasoline.
It's abig part of ourbusiness, you areright, but maybe not as bigas you might expect given thecompetitive pressures to sell ethanol.
Operator
And next we will hear from Mark Flannery with Credit Suisse.
Mark Flannery -Credit Suisse
Thanks very much, and good luck, Ken. We aregoing to miss you.
Ken Matheny
Thank you.
Mark Flannery -Credit Suisse
And I hope Howard can keep himself inline without your guiding hand. Myquestion is to Gary Heminger on theDetroit project.
Gary, how firm or how confidentdo you feel inthe pricing, thecapital pricing for this project, $1.9 billion is areasonably large amount of money, but we have seen these kinds of numbers geta lot bigger, alot quicker than people expected, naming no names around thesector. Sohave you done a lot ofdetailed work there on how much thecoker will cost todayand not just sort of rollthings forward from Garyville?
Could youjust talk a littlebit?
Gary Heminger
Yes, Mark, we have. Wehave gone through, just as we did theGaryville project, we have gone through avery detailed feed process and we have not hurried thefeed.
We have stayed right inline with our Flor, who is our lead contractor and avery large team of Marathon engineering staff that, very similar to theway we did Garyville as we followed through theprocess. And then as, we tested themarket in and around theMidwest, where we will pull thepipe fitters, laborers, and welders to beable to do this workand like Garyville, we went out and procured some of thelong lead equipmentsuch as the coker,some of the heavywall, vessels that arerequired, and some piping as well.
Sowe feel very comfortable with where we sit on this project and we have also hada very renowned thirdparty audit this, this number to make sure that we arecomfortable as well.
Mark Flannery
I guess my follow-up there is, could you give us some ideaof how much of the$1.9 billion will beequipment and sort of stuff and how much will belabor?
Gary Heminger
Well, let mebreak it down this wayfor you a little bit. About $150 million of the$1.9 billion will bepipeline and some off-site connections that we're going to have to make within thepipeline.
Sothat leaves about $1.750 billion for thepipeline. Excuse me, for therefinery project.
Thenew construction versus therevamp is probably thebest way to be able toanswer that, Mark. About $1.2 billionwill be for newconstruction, which will bethe vessels, piping,and pumps compressors, soforth.
And about $600 million or sowill be for revampwork. Therevamp work, of course, will take more labor.
I can getback to you. I donot have a, thebreakdown of how many hours for each and I can have Howard getthat back to you at alater time, Mark.
Mark Flannery -Credit Suisse
That's great. That'sgood enough for now.
Thank you verymuch.
Gary Heminger
Allright.
Operator
Next we will hear from Nicki Decker with Bear Stearns.
Nicki Decker - BearStearns
Good afternoon, Ken. Congratulations,best wishes.
Thanks for everything.
Ken Matheny
Thank you.
Nicki Decker - BearStearns
Just continuing on, on Detroit, Gary, you talked about thepipeline. Is this thepipeline that connects therefinery to the heavycrude infrastructure?
Gary Heminger
Yes, Nicki, the$150 million for total pipeline and offsite that would befrom an area calledSamaria, up to Detroit. Sowe will tie intoEnbridge and Enbridge already hasa pipe that comes downfrom Hardisty down and there, as you recall, they aregoing to expand from Superior, Wisconsin, down to Patoka and then they alreadyhave a line inplace as well that we take crude into Detroit today that runs from thePatoka area up to anarea called Stockbridge.
Sothis incremental pipeline is for Marathon's piece is only for the29 miles ofpipe that we will work on from Samaria to Detroit.
Nicki Decker - BearStearns
Okay. That's helpful.
And if I could slip one more in, wouldyou just talk about where you areon your assessment of projects atSt. Paul Park and Robinson?
Gary Heminger
Sure. Just completingthis, this project feed and infact when you complete thefeed check estimate, now we go inand have tremendous amount of procedural work to doon haz ops and further detailed design, that we still have avery high level team studying theopportunities in andaround St.
Paul and Robinson. I would sayright now, Nicki, that they arestill at avery high-level feasibility stage and we have alot to say grace overwith the two majorprojects that we have ongoing right now.
Nicki Decker - BearStearns
Thank you.
Operator
And next we will hear from Neil McMahon with SanfordBernstein.
Neil McMahon -Sanford Bernstein
Hi, good luck, Ken, and thanks for your help over theyears.
Ken Matheny
Thanks, Neil.
Neil McMahon -Sanford Bernstein
I've just got one question. Really looking atproduction growth going into next year, this is how I amgoing to make two questions out of itat least, just lookingat theLibyan volumes in thethird quarter, they have gone up over thefirst two quarters and not up to thesort of levels you got to last year, but could we seethe level achieved inthe third quarter as agood run rate goinginto 2007?
Gary Heminger
Yes Neil, areyou talking just Libya, or areyou talking in total?
Neil McMahon - SanfordBernstein
I'm talking just, just Libya atthe minute becausethey were down versus where they from where they were last year.
Gary Heminger
No, I think that's agood expectation, how we'll run into, into 2008 and with Libya. I will remind you though, last year they werehigher because we were actually making up for some historical under lift thatwe had as well.
Soif you remove that, we actually have had growth inour Libya production, primarily just aresult of going inthere and making the facilitiesa bit more efficient.
Neil McMahon -Sanford Bernstein
Sure, I appreciate that. That's why I was really looking atis the 50,000 aday sort of level theright level to bethinking about next year, relevant on a40,000 aday, which has been therun rate inthe first fewquarters?
Gary Heminger
No, I think that's afair, a fair estimateto make.
Neil McMahon -Sanford Bernstein
And just thesecond one, again, looking atthe volumes, obviouslyyou have mentioned that you hope to getEG back on through themiddle of November, through thestart of December and also on Alfine, hopefully, getting that up and running inthe first quarter,which has beendelayed. What's thewiggle room on those?
Areyou pretty confident that they aregoing to come in asyou have outlined them?
Gary Heminger
Well, on for theLNG train and EG, we're putting itback together now. Sowe feel very comfortable, there's always this time early inthe operation of thenew facility, there's always thepotential for something else to crop up.
Sowe think the wiggleroom around EG startup is plus or minus two weeks or sofrom an operationalstandpoint. On Alfine, I think I feel pretty good about where we seeour commissioning activity, remaining commission activity going and probablyone of the biggestrisks we have is that as we look to sail away inDecember and out to locations inJanuary there's aweather window there that's going to bethe biggest riskfactor.
Soit's just difficult to predict theweather, to give you arange on that uncertainty.
Neil McMahon -Sanford Bernstein
Okay, great.
Operator
Next we'll hear from John Herrlin with Merrill Lynch.
John Herrlin -Merrill Lynch
Yes, thank you. Inthe Central Gulf Sale205, you were third highest bidder, spent about $220 million.
Could you give us asense of where they were looking, one, atmore Miocene oriented projects versus lower tertiary, and when you expect tomature some of theprospects of theleases you got?
Phil Behrman
Yes, John, this is Phil Behrman. As you know, we won27 blocks.
Thebulk of the blocksthat we, especially our high bidblocks were allMiocene plays. We also had some of thelower tertiary, but thebulk of our activity and our leasing were inthe Miocene trend.
As you know, we haven't been awarded themajority of these blocks, soit's difficult to pin down thetime in drilling, butassuming within thenext 90 days we getawarded the blocks, wewould envision drilling inthe 2009 to 2010timeframe for some of these blocks. Someof them could be alittle bit earlier.
Some of them could bea little bit later. That's pretty much coincides fairly well with our rigcontracting strategy, where we have rigcapacity to go ahead and drill these opportunities.
John Herrlin -Merrill Lynch
Great, thank you.
Operator
Next we'll hear from Mark Gilman with TheBenchmark Company.
Mark Gilman - The Benchmark Company
Good afternoon, guys. Some things related to Western and theanalysis in thepacket if I could please.
First, give usan idea what kind ofDD&A charge you're going to burden theincome statement with? Maybe it's aquestion for Janet.
Janet Clark
Yes, Mark, this is Janet. As you know, purchase price allocation issomething that takes abit of time to complete.
We're makinggood progress there, and I think that probably we're not going to getinto any detail of accounting disclosure on that until we've completed thatprocess.
Mark Gilman - The Benchmark Company
Okay. Gary, interms of the illustrationthat you went through, you chose ahydrogen upgrading technique.
Would itlook any different if you used [lay] coking?
Gary Heminger
Well, yes, Mark, itcertainly would, but what we used was what we seeto be themost prevalent upgrading solutions going on and where we had, you know, theAOSPV upgrading solution, we thought that was really the, thecorrect market barometer to compare against.
Operator
Next we will hear from Paul Cheng with Lehman Brothers.
Paul Cheng - LehmanBrothers
Hi, good afternoon. Kenjust wanted to add my congratulations and thank you for allthe years with thehelp.
Ken Matheny
Thank you, Paul.
Paul Cheng - LehmanBrothers
I think two questions. One is for Steve, wondering if you can give usupdate about Bakken Shale given EOGhas made some prettyoptimistic comment on that.
Steve Hinchman
I would behappy to. TheBakken Shale, we have roughly around 200,000 acres and of coursemost of this year we've really focused on evaluating our acreage.
It's spread out across thebasin. We drilled about 30 wells and aswe look at theareas that now we feel have development potential and arebeginning to focus our efforts now into development, we have typically seenwells that have IP’s over thefirst couple of days, of anywhere from 650 to 850 barrels of oil equivalent perday.
Now, what we typically report and what we've reported to youand what we report to thestate are really30-day averages, and these wells decline quite sharply and our 30-day average hasbeen around 300 to 350 barrels of oil equivalent perday, which is pretty much inline with our expectations. Sonow through our evaluation process, we have afeel where we think thebetter parts of theBakken are, so we'regoing through an effortnow to look to optimize and high grade our acreage position, as well as to go innow more aggressively and execute on development on theareas that we feel good about.
Sowe're currently running sixrigs. We've ramped up now to sixrigs and we'll likely add two additional as we go into early next year.
Sowe'll run at aroundeight rigs, pretty healthy pace.
Paul Cheng - LehmanBrothers
Steve, what's your production rateright now?
Steve Hinchman
Production outof the Bakken rightnow is a little over2,000 barrels a day, online.
Paul Cheng - LehmanBrothers
Net to you or gross?
Steve Hinchman
That would benet.
Paul Cheng - LehmanBrothers
Thank you. I thinkthat the next questionis for Gary.
Gary, on ethanol blending,when are you guysgoing to start blending inthe Southeast Floridaand Georgia?
Gary Heminger
Paul, we are-- in fact, we'realready blending insome parts of the Southeast. We arejust finalizing with thestate of Georgia, having just completed thestate of Tennessee, on what thespecs are inorder to be able tomeet the blendingcomponents.
But we will finish by June of next year allof our terminals to have online blending inthe Southeast. Soas I stated, we're already inTennessee, Georgia.
Cliff just joinedme, are we inthe Carolinas atall?
Clifford Cook
Yes, we have inBelton, South Carolina, we're blending today, and we have thefacilities and theterminals in Florida. We're hopeful that maybe by theJanuary 1st, that Florida will adopt thesame rules that Tennessee and Georgia have recently adopted on state gasolinespecs, which would allow us to blend inFlorida without putting aspecial grade of gasoline into that state.
Operator
(Operator Instructions) We'll movenext to Stephen Beck with Jefferies & Company.
Stephen Beck -Jefferies & Company
Thank you. Myquestion was just answered.
Thank you.
Operator
And we will movenext to Michael LaMotte with JPMorgan.
Michael LaMotte -JPMorgan
Thank you, and good afternoon. I apologize if this question's been addressed.
I did geton the call alittle late. Inthe press release forDetroit, it mentioned 400,000 gallons perday of clean fuel capacity.
I waswondering if you could address theflexibility that you're going to build into this system interms of taking advantage of ULSD and gasoline variances and product.
Gary Heminger
Yes, Michael, and that question had not been asked. We will have theflexibility.
We expect theincremental output to bevery minor because this really is anupgrade project and very small expansion project, but we're expecting probablyaround 8000 barrels aday or so of gasoline,3000 to 4000 barrels aday of distillate, but that still gives us apretty good swing inasphalt. As we look through our numbers today, our modeling stillsuggests that asphalt is agood make in thatmarket, but we still have flexibility to take further asphalt out of themarket and run, run that through thecoker and make additional distillate if themarket requires that.
Michael LaMotte -JPMorgan
Okay. That's helpful.
Thank you. And then just afollow-up what kind of protections can you put inplace to make sure that thethroughput is not really disrupted during theexpansion process?
Arethere increased risks of downtime?
Clarence Cazalot
Well, one of thethings that we aredoing is that we aregoing to time this project, and itis timed, to coincide with thebig plant turnaroundfurther down the road. Sowe will have amoderate amount of revamped high-end work that will berequired, but we certainly have, have done alot of revamp work in thepast within our refineries and executed very well, but we'll take everyprecaution in thatrevamp work.
But we've acquired additional property, sothat the coker, theDHT and thesoftware complex aregoing to be built to theback of the refineryand on, on virgin soil, sowe're going to have very little tie-in problems there.
Michael LaMotte -JPMorgan
And minimal loss time, okay. Then lastly, just sort of system-wide, where doyou stand with, if you could provide anupdate on the benzenespecs, where are youwith respect to compliance and what that might mean for scheduled outages in'08 versus '07?
Gary Heminger
Right. we're just, as you know, theMSAID rules were changedearly, well, they were changedand finalized from where we have been expecting mobile source airtoxics to be earlier inthe year, then theywere finalized I think end of thefirst quarter or sothis year.
Sowe are inthe process right nowof just starting to take these projects to feed and, Gary, doyou know, Gary might have thetimeframe of over thenext years on when we will have to dothe work.
Gary Peiffer
I believe we have to have itall completed by theend of 2010, 2011, sowe haven't started any real fieldwork atthis time, as Gary said, we're just making sure we understand regulations andtrying to cost outthe, cost out thecompliance costs, so atthis point, we haven't done much inthe way of anycompliance work other than theengineering.
Michael LaMotte -JPMorgan
Okay. Great, thankyou, guys.
Operator
And we have afollow-up from Mark Gilman with Benchmark Company.
Mark Gilman - The Benchmark Company
For one of theGarry’s, if I could, please, I know this is aconfusing subject, but of the$360 million derivative figure cited inthe release, does thatinclude Gary Peiffer's prior comments regarding theethanol piece, and how much of itwas not offset in thethird quarter by physical market effects?
Gary Peiffer
Yes, Mark, this is Gary Peiffer. That would include theethanol piece.
I guess we have estimatedthat the physicaleffects or the actualbottom line effect that was not offset by physicals was probably inthe neighborhood of$100 million loss. You might recall last year third quarter we had kind of theopposite phenomena occur and atthat time we said itwas about $150 million positive.
Well,this year we think quarter, third quarter '07 to third quarter '06 probably isabout a negative $100million.
Mark Gilman - The Benchmark Company
Okay. Thanks.
Gary Heminger, why theshift to sweet crude’s late inthe third quarter?
Gary Heminger
Just running allthe LPs, Mark, and theway crude was priced, itgave us the best, bestmargin in our system.
Gary Peiffer
Bottom of thebarrel prices, Mark. This is GaryPeiffer.
Were just not attractive, sowe tried to maximize gasoline and distillate production to let thesweet/sour also gave us added incentive to go towards asweeter slice.
Mark Gilman - The Benchmark Company
Okay, guys. Thanks.
Operator
And next we have afollow-up from John Herrlin with Merrill Lynch.
John Herrlin -Merrill Lynch
Yes. Anupstream question, earlier you mentioned more work-over costs both inEurope and the U.S.
inthe third quarter. Should we expect comparable ones inthe fourth quarter, orwas it just moreseasonal activity?
Gary Heminger
Well, I think that inthe U.S. andspecifically in theGulf of Mexico, it wasfailures and some interventions that we had to do, sowe certainly wouldn't expect that to berepeated.
InEurope, a lot of itwas a focus on somework-overs in our brayfield, which will add to production. Bray, year-on-year, ninemonths this year, ninemonths last year, we've really kept thedecline relatively flat inBray by going to lower pressure operations than by doing amore aggressive work-over program inthe field and ithad some benefits for us.
John Herrlin -Merrill Lynch
Thanks.
Operator
And next we have afollow-up from Paul Cheng with Lehman Brothers.
Paul Cheng - LehmanBrothers
Hi, real quick on theEG late end, is there any insurance claim associated with that, or is thecontract liable, or areyou guys going to foot thebill.
Gary Heminger
There's no insurance claim, but itis under warranty.
Paul Cheng - LehmanBrothers
It's under warranty, soyou do not have topay?
Gary Heminger
That's correct.
Paul Cheng - LehmanBrothers
But there's no business interruption ininsurance, that kind of thing, right?
Gary Heminger
Right.
Paul Cheng - LehmanBrothers
Okay, very good thank you.
Gary Heminger
We won't bedown long enough.
Paul Cheng - LehmanBrothers
Okay. Thanks.
Operator
And we also have afollow-up from Mark Gilman.
Mark Gilman - The Benchmark Company
Guys, doyou have any idea what kind of percentage interest you might have inthe second train atEG LNG given the way thesupply alternatives were emerging? Iassume it's going to belower than the 60%from what I'm seeing.
Clarence Cazalot
Mark, I think it's too early to speculate on that, because,as you say, there is along way to go incommercial negotiations, particularly on gassupply. And as you might imagine inan LNG project,particularly one that hasto source, perhaps will source gassupplies from other international sources, it's important to have alignment.
Soat this point, for usto speculate on what our ultimate interest is premature.
Mark Gilman - The Benchmark Company
Okay. Thanks, Clarence.
Operator
We have no further questions inthe queue. I would like to turn theconference back over to Mr.
Matheny for additional or closing remarks.
Ken Matheny
Erica, thank you somuch. We really don't have anyadditional closing remarks, soI thank everybody once again and next quarter.
Operator
That does conclude today's conference. We dothank you for your participation.
Have agreat day.